Seismic data is processed to create digital seismic images that can be interpreted to identify subsurface geologic features including hydrocarbon deposits. The ability to define the location of rock and fluid properties as well as temperature and pressure conditions in the subsurface are crucial to our ability to make the most appropriate choices for well design, purchasing materials, operating safely, and successfully completing projects. Project cost is dependent upon accurate prediction of the position of physical boundaries within the Earth. Decisions include, but are not limited to, budgetary planning, obtaining mineral and lease rights, signing well commitments, permitting rig locations, designing well paths and drilling strategy, preventing subsurface integrity issues by planning proper casing and cementation strategies, and selecting and purchasing appropriate completion and production equipment. Good quality seismic velocities typically result in better digital seismic images as well as more accurate pore pressure predictions, which is critical for many applications such as well design, reservoir and seal quality prediction, identification of potential geo-hazards, and subsurface integrity studies.
Lack of reliable velocities and velocity-pore pressure transform functions away from well locations often leads to incorrect pre-drill pore pressure predictions. Typically, velocity-to-pressure transform functions are empirically derived from well data (e.g., (a) Eaton, B. A, 1975, The Equation for Geopressure Prediction from Well Logs, SPE 5544, and (b) Bowers, G., Pore Pressure Estimation From Velocity Data: Accounting for Overpressure Mechanisms Besides Undercompaction, SPE 27488, 1995, p. 89-95, each of which is incorporated herein by reference in its entirety). But each equation is often applicable only to specific rocks and geographic locations due to differences in geologic histories including sedimentation rate, timing of exposure to specific effective stress-temperature conditions, and degree of diagenetic transformations. A number of studies demonstrate that the use of a combination of basin modeling and seismic imaging leads to better digital seismic images ((a) Petmecky, et al., Improving sub-salt imaging using 3D basin model derived velocities, Marine and Petroleum Geology, 2009, 26, p. 457-463, (b) Lopez, J. L., et al., Integrated shared earth model: 3D pore-pressure prediction and uncertainty analysis, The Leading Edge, January 2004, p. 52-59, (c) Kacewicz, et al., New integrated workflows for improved pore pressure prediction and seismic imaging, 2015, Search and Discovery Article #41705 (Kacewicz, et al.), (d) Liu, Y., N. C. Dutta, D. Vigh, J. Kapoor, C. Hunter, E. Saragoussi, L. Jones, S. Yang, and M. A. Eissa, 2016, Basin-scale integrated earth-model building using rock-physics constraints: The Leading Edge, 35, 141-145. each of which is incorporated herein by reference in its entirety). For example, as discussed in U.S. Pat. No. 9,310,500 and Kacewicz, et al., iterative looping between basin modeling and seismic imaging and the utilization of hybrid velocities may lead to more reliable processing velocities, improved seismic image focus, and improved pore pressure predictions. U.S. Pat. No. 9,310,500 is incorporated herein by reference in its entirety. A need continues to exist in the art for improved digital seismic images, and more specifically, for improved pore pressure predictions.